Method for detecting formation pore pressure by detecting pumps-off gas downhole

ABSTRACT

Methods and systems are described for drilling a well while distinguishing circulated gas or air from pumps-off gas in a drilling fluid at downhole pressure and temperature. A well is drilled with a drilling fluid, drill string, and drill bit. Drilling fluid is pumped through the drill string, drill bit, and into an annulus between the drill string and a wellbore. The drill string comprises one or more sensors sensing a parameter indicative of circulated gas or air in the drilling fluid flowing through the drill string, one or more sensors being behind and near the drill bit. The sensors measuring gas in the drill string may be at the same level as gas detectors in the annulus. The measurements are communicated to a human-readable interface at the surface, allowing an operator to determine if pressure of the wellbore fluid is greater than formation fluid pressure.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of, and claims benefit under 35 U.S.C. § 120 from application Ser. No. 12/004,175, filed Dec. 19, 2007, which is incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

The present disclosure relates in general to methods of drilling wellbores, for example, but not limited to, wellbores for producing hydrocarbons from subterranean formations, and more particularly to methods of distinguishing circulated gases from connection gas or gas influx in a drilling oil or gas well.

BACKGROUND ART

Drilling techniques for producing wellbores to great depths in the earth are well known and are widely used, especially in the exploration for and production of hydrocarbons. These wells are typically produced by the use of a drill bit positioned on the lower end of a drill string which is supported for rotation to cause the bit to drill into the earth with the drilling being stopped periodically, with the drill string being lifted and supported on slips or similar devices so that a new section of pipe can be attached to the top drill pipe section. These drill pipe sections are fitted with upset ends so that they can be threaded with male fittings on one end and female fittings on the other end. These drill pipe sections are typically about 30 feet long and when joined together can be used to drill for great distances into the earth.

In drilling such boreholes into the earth, it is not uncommon to case the upper portions of the well after it has been drilled to a suitable depth. Frequently the diameter of the wellbore is decreased as it is drilled deeper into the earth. These techniques are well known to those skilled in the art.

During drilling a drill string is positioned from a surface into the wellbore and to the bottom of the wellbore so that the bit can be rotated. The bit is typically rotated by passing a drilling fluid downwardly through the drill pipe to drive the drill bit and extend the bottom of the hole downwardly.

Drilling fluids (sometimes referred to herein as drilling muds, or simply muds) are well known and comprise water-based drilling fluid and oil-based drilling fluid. Further specialized drilling fluids, such as drill-in fluids may also be used. The drilling fluids are typically made up to have a specific gravity so that a column of drilling fluid of a height equal to the wellbore depth exerts a bottom hole pressure equal to the anticipated pressure in the formations penetrated by the wellbore over the entire depth of the well. This drilling fluid pressure tends to inhibit the production of gases and oil formation fluids into the wellbore or to the surface when greater than the formation pressure. It also inhibits events such as kicks and blow-outs where high pressure permeable formations are encountered. The industry has developed numerous techniques for detecting such kicks and blow-outs early to prevent significant damage to the drilling apparatus and to prevent blowing the entire mud column out of the wellbore and possibly contaminating the surrounding area with hydrocarbons.

One technique for identifying such high-pressure formations is illustrated in U.S. Pat. Nos. 5,214,251 and 5,354,956. Both these patents are hereby incorporated herein by reference in their entirety. These references disclose methods for detecting large gas bubbles which may be discharged into the wellbore from a high-pressure formation (kicks) and possibly damage the well and blow all the drilling fluid from the well onto the earth surface.

It is highly desirable that such conditions be identified prior to drilling into such high-pressure formations so that the weight of the drilling fluid can be adjusted to prevent the blow-out.

Accordingly, considerable effort has been directed to the development of methods for detecting subtle amounts of gas invading a wellbore as drilling is conducted. It is recognized that it would be desirable to know the pressure of small amounts of gas in the drilling fluid. Many wells are drilled slightly under-balanced. In other words, the drilling fluid is pumped into the drill pipe at a pressure such that the drilling fluid passing through the drill and into the annulus between the outside of the drill pipe and the inside of the borehole is at a pressure slightly less than that anticipated from the formations through which the well passes. This permits the drilling of the well without unduly contaminating the faces and near-wellbore portions of the formations penetrated by the well. Use of over-pressure drilling can force drilling fluid into the formations penetrated by the wellbore. Drilling fluid components in the well formation faces and near-wellbore portions of the formation can be detrimental to the production of fluids from the formation after the well has been completed.

In other instances, the well may be drilled slightly over-balanced but the drilling fluid may have a weight insufficient to maintain over-balance on the well if the pumps are stopped. This is also an under-balanced condition when the pumps are off. Such conditions exist periodically during the drilling operation because it is periodically necessary to stop the pumps, disconnect from the drill pipe and add a new section of drill pipe to allow the drilling to proceed to an even greater depth. The pressure resulting from the weight of the column of the drilling fluid is referred to as a hydrostatic pressure. This hydrostatic pressure also can be greater than or less than the pressure in the formation. Desirably this hydrostatic pressure is to be slightly greater than the pressure in the formations penetrated by the wellbore for a safety perspective. One desire of this invention is to detect the condition of the hydrostatic pressure being slightly less than the pressure in the formations penetrated by the well when these conditions are first observed in the pumps off condition when the hydrostatic pressure in the well is slightly less than in the pumps on condition.

Of course if an over-balance, i.e., a hydrostatic pressure greater than the pressure in the pores of the formations penetrated by the wellbore is used then little, if any, gas will enter the wellbore from the formations during drilling. There may be gas associated with the formation that has been excavated by the bit that is released as the formation cuttings are returned to the surface but the amount of gas present will then be independent of the pumps-on/pumps-off condition. When an over-balanced condition exits, portions of the drilling fluid will enter the permeable formations and constitute an obstacle to the production of fluids from those formations.

In a preferred embodiment the hydrostatic pressure in the well during pumping of the drilling fluid is slightly over-balanced relative to the formation pressure with the hydrostatic pressure being slightly less when the pumps are off, either due to the loss of the friction of the fluid movement or as a result of a slight swabbing effect from lifting the bit off bottom to set the drill string into the slips. In such instances very small amounts of formation gas can enter the wellbore from low permeability formations, such as shale. This gas may exist as a free fluid in the formation or it may be dissolved in water. The presence of this small amount of gas entering the wellbore is indicative that a higher-pressure formation may be exposed in the wellbore. As a result, it is desirable to check this gas periodically to determine whether the amount of gas entering the well under comparable conditions is increasing or stable when pumps are turned on and off.

It is important to recognize the difference in the response of the high pressure low permeability formation compared to the high pressure high permeability formation. The low permeability shale formations encapsulate the high permeability reservoirs and provide the barrier or trap for hydrocarbons which accumulate in these reservoirs. Most low permeability shale achieve pressure equilibrium with those reservoirs. When the high pressure high permeability reservoirs are exposed to the lower pressure mud columns in pumps-on or pumps-off state, the fluids in the formation can flow into the well at high rates and volume and produce the kick that creates the unstable and potentially unsafe condition drilling operators desire to avoid.

When the high pressured low permeability shale is exposed to the lower pressured mud column, the flow into the well is severely limited by the low permeability and there is little risk of creating an unstable or potentially dangerous well condition. Since the shale encapsulates the reservoir and since the shale reaches pressure equilibrium with the reservoir, drillers can use the underbalanced condition created by pumps-off when drilling the overlying low permeability shale and the associated pumps-off gas to determine if the mud weight is sufficiently high to safely drill the high permeability reservoir before exposing the reservoir and risk generating a kick.

The most commonly used methods of making this determination is to separate the gas from the drilling fluid at the surface. This is an effective method for determining how much gas may be in the drilling fluid but unfortunately in a well of any substantial depth it may take two to three hours for this drilling fluid to reach the earth surface. This may be too late to avoid drilling into a high-pressure permeable formation without making adequate preparations. Failure to take adequate preparations before drilling into a permeable high-pressure formation may result in a kick and potential blowout.

If the pressure conditions in the well are such to allow fluids to flow into the wellbore, fluids flowing from the formation may carry gas either dissolved in the fluid (oil or water) or in a free state in the rock into the well which can be easily detected with these surface devices. When the surface measured gas increases, this can be an indication that the formation pressure is greater than the hydrostatic pressure created by the drilling fluid.

An additional factor to consider is that the hydrostatic pressure created by the mud increases as a result of the circulating mud pumps being on due to friction resulting from the resistance to flow in the system. This difference in pressure results in a change in the differential pressure between the formation and the borehole. When the pressure difference is greater into the borehole, then fluid flows more rapidly from the formation into the borehole resulting in a greater amount of gas in the mud. When the formation pressure is greater than the pumps off pressure (without the pressure necessary to overcome friction) higher gas amounts are measured in the mud. Pumps are usually turned off when making connections or to simulate a connection to look for associated increases in gas that may indicate that the pressure in the borehole is less than the pressure in the formation.

The above-described surface detection method is most effective when the pore pressure of the formation lies between the pumps-off and pumps-on pressures. This condition creates the maximum contrast between pumps-off and pumps-on gas content in the mud. It can then be used to narrow the estimate of formation pore pressure to a value that lies between these two pressures. However, as noted previously, the mud at the bottom of the well must be circulating back to the surface to determine if the amount of gas in the mud has increased as a result of turning the pumps off. This can take many hours to do and usually results in a significant delay in understanding if the phenomena is occurring and assessing the magnitude of the formation pressure relative to the drilling fluid pressure. Significant savings could occur in drilling time if the amount of gas in the drilling fluid could be assessed downhole before the fluid is circulated out the well.

Mud being pumped down the well through the drill pipe may contain recirculated gas or may contain air added to the mud through circulation across the shale shakers or introduced as an air bubble at the time drill pipe connections are made at the surface. Applicant's previously filed application Ser. No. 12/004,175 describes how to analyze gas content in drilling fluids in the annulus; however, the most suitable gas detection devices used downhole to monitor gases in the annulus are not capable of distinguishing freshly introduced formation gas from circulated gas. These gases need to be distinguished so as not to lead to a false conclusion that the well is underbalanced due to the detection of circulated gas downhole.

It would be advantageous if methods and systems could be developed to distinguish circulated gas or air from pumps-off gas at downhole pressure and temperature for the purpose of determining if the pressure of the wellbore fluid is greater than the formation fluid pressure. Detection of pumps-off gas downhole would allow the assessment of formation pressure relative to wellbore pressure in a much quicker and timelier manner which would result in a more accurate assessment of formation pore pressure and reduced associated drilling problems such as fluid influxes, lost circulation or wellbore instability.

SUMMARY

In accordance with the present disclosure, it has now been determined that circulated gas can be identified by placing a detector sensitive to the gas in the drill string behind the drill bit, in certain embodiments at the same level as the detectors monitoring the gas present in the annulus, to monitor the amount of gas present in the drilling fluid inside the drill pipe. The detected gas levels can then be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when those gasses pass the detectors monitoring the annulus. In this manner the observed annulus gas volumes can be corrected to remove the effects of circulated gas or air. This could be accomplished by placing detectors sensitive to the gas in the drill string behind and near the bit to assess the amount of gas present. As used herein, “behind and near” the bit means the sensors nearest the bit (when discussing sensors inside the drill pipe only, in the annulus only, or both) should be within 500 feet [150 meters] of the bit, or 400 feet [120 meters], or 300 feet [90 meters], or 200 feet [60 meters], or 100 feet [30 meters], in some case within 50 feet [15 meters] of the bit, so as to allow the gas to enter the well and be measured, with additional detectors optionally placed along the drill string (when discussing sensors inside the drill pipe only, in the annulus only, or both) to assess the movement of the gas out of the well or to detect influxes of gas up the well. For example, sensors inside the drill pipe, and/or in the annulus could be positioned every 2000 feet [614 meters], every 1500 feet [460 meters], every 1000 feet [307 meters] or so back to surface, or at least the previous casing point. This would allow monitoring expansion of the gas with the decrease in hydrostatic pressure as the gases move upward in the well and to detect pressure from additional gases entering the well at a shallower depth. The physical properties of the gases typically found in the drilling fluid at downhole pressures and temperatures may be studied, and the results used to determine the different physical properties of the drilling fluid that could be used to measure the gas content (drilling fluid density, drilling fluid velocity, and the like). Methods and apparatus of the invention are applicable to both on-shore (land-based) and offshore (subsea-based) drilling.

A first aspect of the disclosure is a method of drilling a well while distinguishing circulated gas or air from pumps-off gas in a drilling fluid at downhole pressure and temperature, the method comprising:

-   -   a) drilling a well with a drilling fluid, a drill string, and a         drill bit from an earth surface through a formation, the         drilling fluid being pumped through the drill string, drill bit,         and into an annulus between the drill string and a wellbore, the         drill string comprising one or more sensors sensing a parameter         indicative of circulated gas or air in the drilling fluid         flowing through the drill string, at least one of the sensors         located in the drill string behind and near the drill bit;     -   b) measuring, while drilling, a parameter of the drilling fluid         indicative of circulated gas or air inside the drill string         behind and near the drill bit using the sensors;     -   c) supporting at least one annulus gas sensor by the drill pipe         behind and near the drill bit to sense an amount of gas in the         drilling fluid in the annulus behind and near the drill bit         during pumping at a depth of the at least one annulus gas sensor         (in certain embodiments, one of the sensors monitoring gas         present in the drill string may be at the same level as a sensor         monitoring gas present in the annulus);     -   d) detecting an amount of gas in the drilling fluid in the         annulus behind and near the drill bit using the at least one         annulus gas sensor during drilling periods before and after a         period when pumping has stopped; and     -   e) communicating the results of steps (b)-(d) to a         human-readable interface at the surface while drilling to allow         an operator to compare the amount of gas in the drilling fluid         in the annulus behind and near the drill bit during the periods         before and after the period when pumping has been stopped, and         thus determine if pressure of the wellbore fluid is greater than         formation fluid pressure behind and near the drill bit.

In certain embodiments, the method comprises tracking detected gas levels volumetrically as a function of the drilling fluid volumes pumped to recognize when recirculated gases or air pass detectors monitoring gas content in the annulus. In this manner the observed annulus gas volumes may be corrected to remove the effects of circulated gas or air. In certain embodiments additional sensors sensitive to parameters indicative of circulating gas or air may also be placed along the drill string to assess the movement of recirculated gasses or air out of the well, or to detect influxes of gases up the well. In certain embodiments, one or more physical properties (density, velocity, temperature, pressure, conductivity, resistivity, and the like) of drilling fluids containing recirculating gasses and air typically found in the mud at downhole pressures and temperatures may be measured in real-time, and the real-time measurements compared with measurements obtained using control samples to determine the actual gas content at downhole conditions.

The detecting circulated gas or air inside the drill string, or a physical property indicative of such gasses, whether behind and near the drill bit, distributed along the drill string both inside and outside of the drill pipe (in the annulus), may proceed using any one or more known measuring techniques which are already described in the literature and understood by those in the art. For example, common methods used for gas detection downhole include the methods and apparatus described in U.S. Pat. Nos. 3,872,721; 5,859,430; 6,465,775; and 6,995,369, all of which are incorporated herein by reference, and discussed more fully herein. Techniques for measuring other wellbore fluid properties, from which gas content may be deduced, are described for example in U.S. Pat. Nos. 6,208,586; 5,850,369; 6,640,625, and Published U.S. Pat. Application Nos. 2008047337; 2007227241; and 2007016464, all of which are incorporated herein by reference in their entirety.

Detection of pumps-off gas downhole and communication of that information (or information indicative of the presence of pumps-off gasses) to a human-readable interface at the surface would allow the assessment of formation pressure relative to wellbore pressure in a much quicker and timelier manner, which should result in a more accurate assessment of formation pore pressure and reduced associated drilling problems such as fluid influxes, lost circulation or wellbore instability. In certain embodiments, the method further comprises using the information on whether pressure of the wellbore fluid is greater than the formation fluid pressure to locate a point of lost circulation or a well fluid influx in the well. In yet other methods, the information on location of lost circulation or well fluid influx may be used to diagnose the root cause of the lost circulation or fluid influx. In still other methods, once the root cause of the lost circulation or well fluid influx is diagnosed, the method comprises selecting an appropriate treatment, and placing a well treatment where the problem has developed in the well.

Another aspect of the disclosure comprises a method for detecting pumps-off gas in drilling fluid in a wellbore during drilling from an earth surface and penetrating a plurality of subterranean formations, the method comprising:

-   -   a) pumping drilling fluid through a drill pipe extending into a         wellbore to provide pressure on the drilling fluid in the drill         pipe and discharging drilling fluid from a bottom end of the         drill pipe into a drill bit and an annulus between an outside of         the drill pipe and an inside of the wellbore to drill the         wellbore to a greater depth;     -   b) supporting at least one gas sensor by the drill pipe near the         bottom of the drill pipe and positioned and adapted to sense the         amount of gas in the drilling fluid in the annulus at a depth of         the at least one sensor;     -   c) detecting the amount of gas in the drilling fluid in the         annulus at the level of the at least one sensor during a period         when pumping has been stopped; and     -   d) comparing the amount of gas in the drilling fluid in the         annulus at the level of the at least one sensor during the         period when pumping has been stopped to an amount of gas in the         annulus at the level of the drill bit detected during pumping.

In this method, the comparing step (d) may occur continuously or intermittently during drilling.

Another aspect of the invention is a system for distinguishing circulated gas or air from pumps-off gas in a drilling mud or fluid at downhole pressure and temperature, comprising:

-   -   a) one or more sensors for measuring a parameter indicative of         circulated gas or air in mud flowing through the drill string,         at least one of the sensors located in a drill string behind and         near a drill bit, and at least one sensor for measuring a         parameter indicative of gas or air in an annulus behind and near         the drill bit;     -   b) means for communicating the parameters to a human-readable         interface at the surface; and     -   c) a human-readable interface from which an operator can compare         amounts of gas present in the annulus during pumps-on periods         which occur before and after a pumps-on period to determine if a         pressure of the wellbore fluid is greater than the formation         fluid pressure using the amount of circulated gas or air present         inside the drill string and the annulus behind and near the         drill bit.

The methods and apparatus described herein may provide other benefits, and the methods for obtaining the gas content in the drill string and/or annulus are not limited to the methods and apparatus noted herein; other methods and apparatus may be employed. Certain embodiments may include temperature and pressure measuring sensors in the vicinity of the gas detection sensors for measuring temperature and pressure near the gas sensors and using the temperatures and pressures to correct acoustic measurements.

These and other features of the methods of the disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

FIG. 1 is a schematic diagram of an embodiment in accordance with the present disclosure;

FIG. 2 is a schematic diagram of an alternate embodiment in accordance with the present disclosure; and

FIG. 3 is a logic diagram in flowchart form illustrating a method embodiment in accordance with the present disclosure.

It is to be noted, however, that the appended drawings are not to scale and illustrate only typical embodiments of this disclosure, and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. Identical reference numerals are used throughout the several views for like or similar elements.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the disclosed methods and apparatus. However, it will be understood by those skilled in the art that the methods and apparatus may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

In the discussion of the drawing figures, the same numbers will be used throughout to refer to the same or similar components.

As illustrated in FIG. 1, a wellbore 10 extends from an earth surface 12 through an overburden 14 and through formations 16, 18, 20, 22, 24 and 26. Some of these formations may be oil-bearing or gas-bearing formations while others may be shale formations which contain pressured fluids. A drill pipe (also referred to herein as a drill string) 34 is positioned to extend from the earth surface to a drill bit 36. Drilling fluid is pumped through the drill string as illustrated by arrows 38 and recovered as illustrated by arrows 40. No equipment has been illustrated for performing this operation since such equipment is considered to be well known to those skilled in the art. The drilling fluid injected through lines 38 passes through drill bit 36 and is discharged as illustrated by arrows 40 through an annulus 60 between an inside 44 of wellbore 10 and an outside 62 of drill pipe 34.

As the drilling fluid moves upwardly it is eventually recovered as illustrated by an arrow 42. This drilling fluid is typically passed to a drill cuttings separation section and is typically degassed and adjusted to the desired composition and thereafter reinjected.

As illustrated schematically in FIG. 1, a first enlarged section 46 is positioned on an upper end of the drill pipe 34. A section of enlarged section 48 is positioned on an end of a second drill pipe 50 so that they may be matingly joined. The slips 52 support slightly lifted drill pipe 34 while second pipe section 50 is joined to the drill pipe 34. Such techniques are considered to be well known to those skilled in the art and do not require further description. A centralizer 58 is commonly used to maintain drill pipe 34 in a central portion of the wellbore.

Sensors 54 for sensing gas or a parameter indicative of gas in the annulus are illustrated near a bottom 64 of the drill string. Sensors 54 are referred to herein as “annulus sensors” for reasons that will become apparent. Annulus sensors 54 are desirably placed at a distance from about 1 to about 200 feet (about 0.3 meter to about 60 meters) above the bottom 64 of drill pipe 34. Annulus sensors 54 may be positioned as a portion of a drill pipe section or they may be attached to the inside or the outside of the drill pipe. With some types of sensors the annulus sensors 54 could be positioned inside drill pipe 34. In certain embodiments, the annulus sensors 54 for sensing gas or parameter indicative of gas in the annulus may be positioned in the drill pipe; in other embodiments, the annulus sensors 54 for sensing gas or parameter indicative of gas in the annulus may be positioned on the outside of the drill pipe. Annulus sensors 54 are effective to sense the amount of gas contained in the drilling fluid in the annulus, particularly to distinguish the amount of gas during times when the pumps are turned off compared to the amount of gas when pumps are on. The pressure reduction in the drilling fluid during a pumps-off condition will be substantially less in some wells (as high as 300 psi, about 2 MPa, in some cases) than when the drilling fluid pumps are on. This allows the relatively accurate measurement of the amount of gas entering the wellbore annulus from the formations during the times when the pumps are turned off. This provides an accurate basis for estimating the amount of pressure generated by the formation against the hydrostatic pressure of the drilling fluid. This information is desirably transmitted up the drill string as known to those skilled in the art, by connectors passing along the drill string. While not illustrated in FIG. 1, a plurality of annulus sensors 54 could be used. The plurality of annulus sensors 54 could be distributed along drill pipe 62 from drill bit 36 back to the surface. Annulus sensors 54 provide information which can be used to determine the amount of gas in the drilling fluid at the bottom of the well during periods when the pumps are shut down.

As noted previously, drilling fluid being pumped down the well through the drill pipe may contain recirculated gas or may contain air added to the drilling fluid through circulation across the shale shakers or introduced as an air bubble at the time drill pipe connections are made at the surface. The most suitable gas detection devices used downhole to monitor the annulus, such as annulus sensors 54 in FIG. 1, are not capable of distinguishing freshly introduced formation gas from circulated gas. These gases need to be distinguished so as not to lead to a false conclusion that the well is underbalanced due to the detection of circulated gas downhole.

Referring again to FIG. 1, it has now been determined that recirculated and/or air gas can be identified and distinguished from fresh influx gas in the wellbore by placing one or more sensors 55 sensitive to the recirculating gas and/or air gas in the drill string behind the drill bit, in certain embodiments at the same level as annulus sensors 54 (although not necessarily) to monitor the amount of gas present in the drilling fluid inside the drill pipe. Sensors 55 will be referred to herein as “drill string sensors” to distinguish them from annulus sensors 54. The detected internal drill string gas levels can then be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when recirculating gasses and/or air pass annulus sensors 54. In this manner the observed annulus gas volumes measured by annulus sensors 54 may be corrected to remove the effects of circulated gas and/or air measured by drill string sensors 55.

As illustrated in FIG. 1, drill string sensors 55 for sensing gas or a parameter indicative of gas in the drill string are illustrated near a bottom 64 of the drill string, similar to the position of annulus sensors 54, although this is mainly for convenience, and is not strictly necessary. Drill string sensors 55 are desirably placed at a distance from about 1 to about 200 feet (about 0.3 meter to about 60 meters) above the bottom 64 of drill pipe 34. Drill string sensors 55 may be positioned as a portion of a drill pipe section or they may be attached to the inside or the outside of the drill pipe. With some types of sensors the drill string sensors 55 could be positioned inside drill pipe 34. In certain embodiments, drill string sensors 55 for sensing gas or parameter indicative of gas in the drill string may be positioned in the drill pipe; in other embodiments, drill string sensors 55 for sensing gas or parameter indicative of gas in the drill string may be positioned on the outside of the drill pipe. Drill string sensors 55 are effective to sense the amount of gas contained in the drilling fluid in the drill string during drilling fluid flow or during period of no or little drilling fluid flow in the drill string. This information allows correction of the annulus sensors 54 and provides a more accurate basis for estimating the amount of pressure generated by the formation against the hydrostatic pressure of the drilling fluid. This information is desirably transmitted up the drill string as known to those skilled in the art, by connectors passing along the drill string. While not illustrated in FIG. 1, a plurality of drill string sensors 55 could be used. The plurality of drill string sensors 55 could be distributed along drill pipe 62 from drill bit 36 back to the surface.

The sensors 54 and 55 may be of any suitable type, such as pulse-echo, density, ultrasonic, velocity, sonic impedance, acoustic impedance and the like, as known to those skilled in the art. They may be the same or different from each other. In certain embodiments, sensors 54 will be all one type, while sensors 55 will all be of a different type. In certain other embodiments, all sensors 54 and 55 will be identical in operation. The particular type sensors required are not considered to constitute part of the present disclosure but rather the use of the sensors to perform the methods claimed in the present disclosure is considered to constitute the present disclosure. Sensors 54 and 55 could be positioned on, inside or outside of the drill pipe and adapted to detect comparable values for the drill fluid in the drill pipe and in the annulus.

In FIG. 2 a second embodiment of the present invention is illustrated. In this embodiment the upper portion of wellbore 10 has been cased with a casing 30 supported in place in the wellbore by cement 32. The drilling fluid is injected as described through drill pipe 34 as illustrated by arrows 38 with the drilling fluid being passed downwardly through drill pipe 34, out through drill bit 36 and upwardly through the annulus as illustrated by arrows 40 to recovery through a recovery line 42. In this embodiment, a centralizer 58 is also used. In addition to annulus sensors 54 and drill string sensors 55 positioned near a bottom 64 of drill pipe 34, a plurality of sensors 54 and 55 are arranged along the length of drill pipe 34. Sensors 54 will affect a measurement of the amount of gas which may be leaking into the wellbore at levels above the bottom of the wellbore. This can be of considerable interest in the event that formations penetrated by the wellbore tend to become more active in releasing materials into the wellbore at the hydrostatic pressure of the drilling fluid. It will be noted that the hydrostatic pressure of the drilling fluid will be somewhat less at the upper portions of the formation than at the bottom of the wellbore.

By the use of the methods of the present disclosure, circulated gas can be identified and an amount of gas present in the drilling fluid inside the drill pipe may be quantified. The detected gas levels can be tracked volumetrically as a function of the drilling fluid volumes pumped to recognize when those gasses pass the detectors monitoring the annulus. In this manner the observed annulus gas volumes can be corrected to remove the effects of circulated gas or air. Furthermore, gas concentration in the drilling fluid may be determined during a pumps-off period and then may be compared to a standard gas amount to determine whether the weight of the drilling fluid should be increased or whether other steps should be taken to control the wellbore. Particularly, it may be desirable to compare this gas measurement to previous gas measurements in the same well taken at an earlier pumps-off period or while the pumps were on. Desirably the gas concentration is measured at each pumps-off period and more frequently if significant changes are detected. This provides an indication as to whether the pressure in the formation is increasing relative to the pressure in the well as indicated by the result of gases entering the wellbore increasing at pumps-off conditions. Alternatively, other standards can be adopted to determine whether amounts of gases entering the wellbore are excessive. By the methods of the present disclosure, upon the drill bit approaching a high pressure formation, an increase in gas entry into the bottom of the wellbore will be detected. This enables the operator to weight the drilling fluid more heavily to impose a back pressure upon the drilling fluid contained in the annulus or the like to control the well.

By the methods of the present disclosure, upon the drill bit approaching a high pressure formation, an increase in gas entry into the bottom of the wellbore will be detected. This enables the operator to weight the drilling fluid more heavily to impose a back pressure upon the drilling fluid contained in the annulus or the like to control the well.

The methods of the present disclosure provide an effective method for determining a meaningful number related to conditions at the bottom of the borehole in substantially real time. The amount of gas contained in the drilling fluid is indicative of the amount of gas-containing materials entering the wellbore annulus from the surrounding formations. Furthermore, knowledge of the recirculating gasses or air allows correction of the measured annulus gas amounts. This information is very helpful in controlling the well, adjusting the weight of the drilling fluid and the like.

By the methods of the present disclosure, quantities of gas on the order of 0.01 and up to in excess of 5.0 vol. % as measured at surface conditions or greater can be detected downhole. Typically these methods will detect relatively small amounts of gas in the drilling fluid near the downhole annulus sensor to enable the detection of trends. These quantities of gas do not exert appreciable pressure and are detectable at the wellhead using conventional gas detection techniques and while indicative of gas invasion into the well, are not normally detected downhole by existing testing systems for detecting large gas bubbles. The methods of the present disclosure enable early detection of increasing gas levels before the gas concentrations can reach problematic levels. These methods may be used by comparing successive annulus gas readings under similar conditions, as well as comparing to gas measured in the drill string by the drill string sensors. An increase in annulus gas from about 1 to about 3 times a background or baseline value is of great concern. The background or baseline value may be a previous quantitative measurement of annulus gas, a measurement of drill string gas, or another indicia of the background conditions. This early detection enables the driller to take corrective action much earlier than if the drilling fluid were analyzed for the same or similar information at the surface.

FIG. 3 illustrates a method embodiment of the present disclosure in flowchart form. Embodiment 300 of FIG. 3 illustrates in box 302 drilling a well with a drilling fluid, a drill string, and a drill bit from an earth surface through a formation. Box 304 illustrates pumping the drilling fluid through the drill string, drill bit, and into an annulus between the drill string and a wellbore. It should be pointed out that the steps illustrated in FIG. 3 are merely for illustrating the concepts of the disclosure; it is not intended that the steps must be taken sequentially or in parallel. Box 306 indicates measuring, while drilling, a parameter of the drilling fluid indicative of circulated gas or air inside the drill string behind and near the drill bit using one or more sensors. Box 305 illustrates supporting at least one annulus gas sensor by the drill pipe near the bottom of the drill pipe and positioned to sense the amount of gas in the drilling fluid in the annulus at a depth of the at least one annulus gas sensor. Box 307 illustrates periodically stopping pumping, and detecting the amount of gas in the drilling fluid in the annulus at the level of the at least one sensor during pumping periods before and after stopping of pumping. In embodiment 300, the next step, illustrated by box 308 is communicating the result to a human-readable interface at the surface. Box 310 illustrates comparing the amount of gas in the drilling fluid in the annulus at the level of the at least one sensor during the pumping periods.

In accordance with the present disclosure, a primary interest lies in using one or more of the methods and apparatus described above to correct observed annulus gas volumes to remove the effects of circulated gas or air, and using this information to diagnose, make decisions on, and implement changes to drilling fluid weight, density, or other parameter. The skilled operator or designer will determine which methods, apparatus and drilling fluids are best suited for a particular well and formation to achieve the highest efficiency without undue experimentation.

Methods and apparatus in accordance with the present disclosure may include means for measuring drilling fluid temperature and annular fluid pressure of fluids flow (or not flowing) inside the drill string, and/or flowing (or not flowing) in the annulus. Suitable temperature measurement means include thermocouples, thermistors, resistant temperature detectors (RTDs), and the like. Suitable fluid pressure measurement means include piezoelectric sensors, fiber optic sensors, strain gauges, microelectromechanical (MEMS) sensors, and the like. The apparatus and methods of the present disclosure may also include means for calculating temperature- and pressure-corrected measurement values using the measured temperatures and fluid pressures. Suitable means for calculating include digital computers, and the like, either hard-wired or wirelessly connected to the drill string or tools in the drill string, and which may include wired or wireless connections to human-readable devices, such as video CRT screens, printers, and the like.

Useful drilling muds for use in the methods of the present disclosure include water-based, oil-based, and synthetic-based muds. The choice of formulation used is dictated in part by the nature of the formation in which drilling is to take place. For example, in various types of shale formations, the use of conventional water-based muds can result in a deterioration and collapse of the formation. The use of an oil-based formulation may circumvent this problem. A list of useful muds would include, but not be limited to, conventional muds, gas-cut muds (such as air-cut muds), balanced-activity oil muds, buffered muds, calcium muds, deflocculated muds, diesel-oil muds, emulsion muds (including oil emulsion muds), gyp muds, oil-invert emulsion oil muds, inhibitive muds, kill-weight muds, lime muds, low-colloid oil muds, low solids muds, magnetic muds, milk emulsion muds, native solids muds, PHPA (partially-hydrolyzed polyacrylamide) muds, potassium muds, red muds, saltwater (including seawater) muds, silicate muds, spud muds, thermally-activated muds, unweighted muds, weighted muds, water muds, and combinations of these.

Useful mud additives include, but are not limited to asphaltic mud additives, viscosity modifiers, emulsifying agents (for example, but not limited to, alkaline soaps of fatty acids), wetting agents (for example, but not limited to dodecylbenzene sulfonate), water (generally a NaCl or CaCl₂ brine), barite, barium sulfate, or other weighting agents, and normally amine treated clays (employed as a viscosification agent). More recently, neutralized sulfonated ionomers have been found to be particularly useful as viscosification agents in oil-based drilling muds. See, for example, U.S. Pat. Nos. 4,442,011 and 4,447,338, both incorporated herein by reference. These neutralized sulfonated ionomers are prepared by sulfonating an unsaturated polymer such as butyl rubber, EPDM terpolymer, partially hydrogenated polyisoprenes and polybutadienes. The sulfonated polymer is then neutralized with a base and thereafter steam stripped to remove the free carboxylic acid formed and to provide a neutralized sulfonated polymer crumb.

The mud system used may be an open or closed system. Any system used should allow for samples of circulating mud to be taken periodically, whether from a mud flow line, a mud return line, mud motor intake or discharge, mud house, mud pit, mud hopper, or two or more of these.

In actual operation, depending on the mud report from the mud engineer, the drilling rig operator (or owner of the well) has the opportunity to adjust the density, specific gravity, weight, viscosity, water content, oil content, composition, pH, flow rate, solids content, solids particle size distribution, resistivity, conductivity, and combinations of these properties of the mud. The mud report may be in paper format, or more likely today, electronic in format. The change in one or more of the list parameters and properties may be tracked, trended, and changed by a human operator (open-loop system) or by an automated system of sensors, controllers, analyzers, pumps, mixers, agitators (closed-loop systems).

“Drilling” as used herein may include, but is not limited to, rotational drilling, directional drilling, non-directional (straight or linear) drilling, deviated drilling, geosteering, horizontal drilling, and the like. Rotational drilling may involve rotation of the entire drill string, or local rotation downhole using a drilling mud motor, where by pumping mud through the mud motor, the bit turns while the drillstring does not rotate or turns at a reduced rate, allowing the bit to drill in the direction it points. A turbodrill may be one tool used in the latter scenario. A turbodrill is a downhole assembly of bit and motor in which the bit alone is rotated by means of fluid turbine which is activated by the drilling mud. The mud turbine is usually placed just above the bit.

“Bit” or “drill bit”, as used herein, includes, but is not limited to antiwhirl bits, bicenter bits, diamond bits, drag bits, fixed-cutter bits, polycrystalline diamond compact bits, roller-cone bits, and the like. The choice of bit, like the choice of drilling mud, is dictated in part by the nature of the formation in which drilling is to take place.

The rate of penetration (ROP) during drilling methods of this disclosure depends on permeability of the rock (the capacity of a porous rock formation to allow fluid to flow within the interconnecting pore network), the porosity of the rock (the volume of pore spaces between mineral grains expressed as a percentage of the total rock volume, and thus a measure of the capacity of the rock to hold oil, gas, or water), and the amount or percentage of vugs. Generally the operator or owner of the well wishes the ROP to be as high as possible toward a known trap (any geological structure which precludes the migration of oil and gas through subsurface rocks, causing the hydrocarbons to accumulate into pools), without excess tripping in and out of the wellbore. In accordance with the present disclosure the drilling contractor or operator is able to drill more confidently and safely, knowing the pore pressure in the formation ahead of the drill bit before the drill bit actually penetrates the hydrocarbon-bearing region.

From the foregoing detailed description of specific embodiments, it should be apparent that patentable methods and apparatus have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the methods and apparatus, and is not intended to be limiting with respect to the scope of the methods and apparatus. It is contemplated that various substitutions, alterations, and/or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. 

1. A method of drilling a well while distinguishing circulated gas or air from pumps-off gas in a drilling fluid at downhole pressure and temperature, the method comprising: a) drilling a well with a drilling fluid, a drill string, and a drill bit from an earth surface through a formation, the drilling fluid being pumped through the drill string, drill bit, and into an annulus between the drill string and a wellbore, the drill string comprising one or more sensors sensing a parameter indicative of circulated gas or air in the drilling fluid flowing through the drill string, at least one of the sensors located in the drill string behind and near the drill bit; b) measuring, while drilling, a parameter of the drilling fluid indicative of circulated gas or air inside the drill string behind and near the drill bit using the sensors; c) supporting at least one annulus gas sensor by the drill pipe behind and near the drill bit to sense an amount of gas in the drilling fluid in the annulus behind and near the drill bit during pumping at a depth of the at least one annulus gas sensor; d) detecting an amount of gas in the drilling fluid in the annulus behind and near the drill bit using the at least one annulus gas sensor during drilling periods before and after a period when pumping has stopped; and e) communicating the result of steps (b)-(d) to a human-readable interface at the surface while drilling to allow an operator to compare the amount of gas in the drilling fluid in the annulus behind and near the drill bit during the periods before and after the period when pumping has been stopped, and thus determine if pressure of the wellbore fluid is greater than formation fluid pressure behind and near the drill bit.
 2. The method of claim 1 wherein the measuring of the parameter of the drilling fluid indicative of circulated gas or air inside the drill string comprises measuring the parameter in the drilling fluid flowing through the drill string at a same level as an annulus gas sensor monitoring gas present in fluid flowing through the annulus.
 3. The method of claim 1 comprising tracking gas levels volumetrically as a function of drilling fluid volumes pumped to recognize when recirculated gasses or air pass sensors monitoring gas content in the annulus.
 4. The method of claim 3 further comprising correcting annulus gas volume to remove effects of circulated gas or air.
 5. The method of claim 1 further comprising sensing parameters indicative of circulating gas or air using sensors placed along the drill string to assess the movement of recirculated gasses or air out of the well, or to detect influxes of gases up the well.
 6. The method of claim 1 wherein the measuring comprises measuring one or more physical properties selected from density, velocity, temperature, pressure, conductivity, and resistivity of drilling fluid containing recirculating gasses and/or air at downhole pressures and temperatures.
 7. The method of claim 6 wherein the physical property is measured in real-time, and the real-time measurements compared with measurements obtained using control samples to determine the actual gas content at downhole conditions.
 8. The method of claim 1 wherein the measuring employs a technique selected from pulse-echo, density, ultrasonic, velocity, sonic impedance, acoustic impedance, and combinations thereof.
 9. The method of claim 1 further comprising assessing formation pressure relative to wellbore pressure and adjusting a parameter of the drilling fluid.
 10. The method of claim 9 wherein the parameter of the drilling fluid is selected from weight, density, specific gravity, API gravity, thermal conductivity, pH, viscosity, compressibility, thermal conductivity, salinity, and water activity.
 11. A method for detecting pumps-off gas in drilling fluid in a wellbore during drilling from an earth surface and penetrating a plurality of subterranean formations, the method comprising: a) pumping drilling fluid through a drill pipe extending into a wellbore to provide pressure on the drilling fluid in the drill pipe and discharging drilling fluid from a bottom end of the drill pipe into a drill bit and an annulus between an outside of the drill pipe and an inside of the wellbore to drill the wellbore to a greater depth; b) supporting at least one gas sensor by the drill pipe near the bottom of the drill pipe and positioned and sensing the amount of gas in the drilling fluid in the annulus at a depth of the at least one sensor; c) periodically stopping the pumping of the drilling fluid for one or more time periods; and d) comparing amounts of gas detected by the at least one sensor in the drilling fluid in the annulus at the level of the at least one sensor during pumping time periods to determine a change in an amount of gas in the annulus resulting from the periodic stopping of pumping.
 12. The method of claim 11 wherein the wellbore is drilled to a greater depth at an under-balanced condition.
 13. The method of claim 11 wherein the wellbore is at an under-balanced condition during one or more of the periods when pumping has been stopped.
 14. The method of claim 11 wherein the wellbore is at an under-balanced condition at a hydrostatic drilling fluid pressure.
 15. The method of claim 11 wherein a pore pressure of the subterranean formations penetrated by the drill pipe is between a drilling fluid pumping pressure and a hydrostatic drilling fluid pressure.
 16. The method of claim 11 wherein the at least one sensor is mounted in a section of drill pipe.
 17. The method of claim 11 wherein the at least one sensor is mounted on the outside of the drill pipe.
 18. The method of claim 11 wherein the sensor is selected from the group consisting of pulse-echo, density, ultrasonic, velocity, sonic impedance and acoustic impedance sensors.
 19. The method of claim 11 wherein the amount of gas in the drilling fluid during a period when pumping has been stopped is compared to a previous amount of gas detected during a previous period when pumping had been stopped.
 20. The method of claim 11 wherein a plurality of sensors are positioned at a plurality of locations along a length of the drill pipe.
 21. The method of claim 11 wherein at least one of the pluralities of sensors is positioned at a distance from about 1 to about 1500 feet [460 meters] above the drill bit along a length of drill pipe.
 22. The method of claim 11 wherein the wellbore is at an under-balanced condition during pumping.
 23. The method of claim 1 wherein an upper portion of the wellbore is cased.
 24. A system for distinguishing circulated gas or air from pumps-off gas in a drilling mud or fluid at downhole pressure and temperature, comprising: a) one or more sensors for measuring a parameter indicative of circulated gas or air in mud flowing through the drill string, at least one of the sensors located in a drill string behind and near a drill bit, and at least one sensor for measuring a parameter indicative of gas or air in an annulus behind and near the drill bit; b) means for communicating the parameters to a human-readable interface at the surface; and c) a human-readable interface from which an operator can compare amounts of gas present in the annulus during pumps-on periods which occur before and after a pumps-off period to determine if a pressure of the wellbore fluid is greater than the formation fluid pressure using the amount of circulated gas or air present inside the drill string and the annulus behind and near the drill bit. 